Downhole system for use in a wellbore and method for the same
A downhole system for use in a wellbore that includes a work string having a downhole end; a setting sleeve coupled with the downhole end; and a downhole tool engaged with the setting sleeve during run-in, the downhole tool further including a mandrel, a first slip, a first cone, a sealing element, and a lower sleeve coupled with the mandrel.
Latest Downhole Technology, LLC Patents:
This application claims the benefit under 35 U.S.C. § 119(e) of U.S. Provisional Patent Application Ser. No. 62/166,191, filed on May 26, 2015; this application is a continuation-in-part of U.S. Non-provisional patent application Ser. No. 14/794,691, filed on Jul. 8, 2015, which is a continuation of U.S. Non-provisional patent application Ser. No. 14/723,931, filed on May 28, 2015, and now issued as U.S. Pat. No. 9,316,086, which is a continuation of U.S. Non-provisional patent application Ser. No. 13/592,004, filed Aug. 22, 2012, and now issued as U.S. Pat. No. 9,074,439, which claims the benefit under 35 U.S.C. § 119(e) of U.S. Provisional Patent Application Ser. No. 61/526,217, filed on Aug. 22, 2011, and U.S. Provisional Patent Application Ser. No. 61/558,207, filed on Nov. 10, 2011. The disclosure of each application is hereby incorporated herein by reference in its entirety for all purposes.
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENTNot applicable.
BACKGROUND Field of the DisclosureThis disclosure generally relates to systems and related tools used in oil and gas wellbores. More specifically, the disclosure relates to downhole system that may be run into a wellbore and useable for wellbore isolation, and methods pertaining to the same. In particular embodiments, the tool may be a composite plug made of drillable materials.
Background of the DisclosureAn oil or gas well includes a wellbore extending into a subterranean formation at some depth below a surface (e.g., Earth's surface), and is usually lined with a tubular, such as casing, to add strength to the well. Many commercially viable hydrocarbon sources are found in “tight” reservoirs, which means the target hydrocarbon product may not be easily extracted. The surrounding formation (e.g., shale) to these reservoirs is typically has low permeability, and it is uneconomical to produce the hydrocarbons (i.e., gas, oil, etc.) in commercial quantities from this formation without the use of drilling accompanied with fracing operations.
Fracing is common in the industry and growing in popularity and general acceptance, and includes the use of a plug set in the wellbore below or beyond the respective target zone, followed by pumping or injecting high pressure frac fluid into the zone. The frac operation results in fractures or “cracks” in the formation that allow hydrocarbons to be more readily extracted and produced by an operator, and may be repeated as desired or necessary until all target zones are fractured.
A frac plug serves the purpose of isolating the target zone for the frac operation. Such a tool is usually constructed of durable metals, with a sealing element being a compressible material that may also expand radially outward to engage the tubular and seal off a section of the wellbore and thus allow an operator to control the passage or flow of fluids. For example, by forming a pressure seal in the wellbore and/or with the tubular, the frac plug allows pressurized fluids or solids to treat the target zone or isolated portion of the formation.
In operation, forces (usually axial relative to the wellbore 106) are applied to the slip(s) 109, 111 and the body 103. As the setting sequence progresses, slip 109 moves in relation to the body 103 and slip 111, the seal member 122 is actuated, and the slips 109, 111 are driven against corresponding conical surfaces 104. This movement axially compresses and/or radially expands the compressible member 122, and the slips 109, 111, which results in these components being urged outward from the tool 102 to contact the inner wall 107. In this manner, the tool 102 provides a seal expected to prevent transfer of fluids from one section 113 of the wellbore across or through the tool 102 to another section 115 (or vice versa, etc.), or to the surface. Tool 102 may also include an interior passage (not shown) that allows fluid communication between section 113 and section 115 when desired by the user. Oftentimes multiple sections are isolated by way of one or more additional plugs (e.g., 102A).
Upon proper setting, the plug may be subjected to high or extreme pressure and temperature conditions, which means the plug must be capable of withstanding these conditions without destruction of the plug or the seal formed by the seal element. High temperatures are generally defined as downhole temperatures above 200° F., and high pressures are generally defined as downhole pressures above 7,500 psi, and even in excess of 15,000 psi. Extreme wellbore conditions may also include high and low pH environments. In these conditions, conventional tools, including those with compressible seal elements, may become ineffective from degradation. For example, the sealing element may melt, solidify, or otherwise lose elasticity, resulting in a loss the ability to form a seal barrier.
Before production operations commence, the plugs must also be removed so that installation of production tubing may occur. This typically occurs by drilling through the set plug, but in some instances the plug can be removed from the wellbore essentially intact. A common problem with retrievable plugs is the accumulation of debris on the top of the plug, which may make it difficult or impossible to engage and remove the plug. Such debris accumulation may also adversely affect the relative movement of various parts within the plug. Furthermore, with current retrieving tools, jarring motions or friction against the well casing may cause accidental unlatching of the retrieving tool (resulting in the tools slipping further into the wellbore), or re-locking of the plug (due to activation of the plug anchor elements). Problems such as these often make it necessary to drill out a plug that was intended to be retrievable.
However, because plugs are required to withstand extreme downhole conditions, they are built for durability and toughness, which often makes the drill-through process difficult. Even drillable plugs are typically constructed of a metal such as cast iron that may be drilled out with a drill bit at the end of a drill string. Steel may also be used in the structural body of the plug to provide structural strength to set the tool. The more metal parts used in the tool, the longer the drilling operation takes. Because metallic components are harder to drill through, this process may require additional trips into and out of the wellbore to replace worn out drill bits.
The use of plugs in a wellbore is not without other problems, as these tools are subject to known failure modes. When the plug is run into position, the slips have a tendency to pre-set before the plug reaches its destination, resulting in damage to the casing and operational delays. Pre-set may result, for example, because of residue or debris (e.g., sand) left from a previous frac. In addition, conventional plugs are known to provide poor sealing, not only with the casing, but also between the plug's components. For example, when the sealing element is placed under compression, its surfaces do not always seal properly with surrounding components (e.g., cones, etc.).
Downhole tools are often activated with a drop ball that is flowed from the surface down to the tool, whereby the pressure of the fluid must be enough to overcome the static pressure and buoyant forces of the wellbore fluid(s) in order for the ball to reach the tool. Frac fluid is also highly pressurized in order to not only transport the fluid into and through the wellbore, but also extend into the formation in order to cause fracture. Accordingly, a downhole tool must be able to withstand these additional higher pressures.
In addition, downhole tool technology has evolved from tools historically used in vertical orientation, which has resulted in new problems. For example, when used in a general horizontal orientation downhole tools, as well as the work string, encounter frictional resistance and gravitational force not otherwise present in a vertical orientation. In some instances, the downhole tool and/or the work string will be off-center, and even contact the surrounding tubular (e.g., casing), for thousands of feet.
Referring briefly to
When the tool 102 is run into the well 106 and through tubular 108, the tool 102 will encounter various forces, including downward force F1, which may be a net force of pressure, gravity, etc. Tool area A1, resembling a circumferential contact region or near-contact region of the mandrel end 114A and the setting sleeve 154 incurs little to no portion of the force F1 because the area is largely parallel to the vector. The conventional tool 102 incorporates the simplest component parts that are cheapest and easily fabricated, which includes machined, linear portions. The tool 102 is easily positionable, and ultimately set, so that a largely concentric and equal annulus is formed between the tool 102 and the casing 108 (see, e.g., annulus arrows 199).
While this type of configuration is sufficient for vertical orientation, very distinct and different problems are encountered when the tool 102 is used in horizontal service.
The most apparent solution for one of skill would be to increase clearance between the mandrel end and the setting sleeve; however, debris, sand, etc. may fill into this clearance, and then there is ultimately no clearance, resulting in a pseudo tolerance fit, as well as other problems caused by the debris that impairs the function of the tool 102.
In operation, when the tool 102 is set, it is often a hydraulic operation and pressurization that occurs in strokes. After the tool 102 is set and released from the string 105, the string 105 needs to be removed from the wellbore 106. The faster the removal of the string 105, the less cost incurred per foot. Increased removal speed per foot becomes paramount when well lengths start to exceed 10,000 feet.
What is needed is a downhole tool with reduced drag that would allow faster pullout.
Accordingly, there are needs in the art for novel systems and methods for isolating wellbores in a viable and economical fashion. There is a great need in the art for downhole plugging tools that form a reliable and resilient seal against a surrounding tubular. There is also a need for a downhole tool made substantially of a drillable material that is easier and faster to drill. There is a great need in the art for a downhole tool that overcomes problems encountered in a horizontal orientation. There is a need in the art to reduce the amount of time and energy needed to remove a workstring from a wellbore, including reducing hydraulic drag. There is a need in the art for non-metallic downhole tools and components.
It is highly desirous for these downhole tools to readily and easily withstand extreme wellbore conditions, and at the same time be cheaper, smaller, lighter, and useable in the presence of high pressures associated with drilling and completion operations.
SUMMARYEmbodiments of the disclosure pertain to a downhole system useable for use in a wellbore that may include a work string comprising a downhole end; a setting sleeve coupled with the downhole end; and a downhole tool engaged with the setting sleeve during run-in.
The downhole tool may include a mandrel. The mandrel may have a distal end; a proximate end; and a mandrel outer surface. There may be a bearing plate disposed around the mandrel.
The downhole tool may include a first slip disposed around the mandrel proximate to the distal end. The first slip may have a one-piece configuration; a first slip outer surface; and an at least one lateral groove in the first slip body that is defined by a depth that extends from the first slip outer surface to a first slip inner surface. The downhole tool may include a first cone disposed around the mandrel, and proximate to a first side of the first slip.
The downhole tool may include a second slip disposed around the mandrel. There may be a second cone disposed around the mandrel, and proximate to a first side of the second slip. There may be a sealing element disposed around the mandrel. The sealing element may be positioned between the first cone and the second cone.
The downhole tool may include a lower sleeve disposed around the mandrel. The lower sleeve may be proximate to a second side of the first slip. The lower sleeve may be coupled with the mandrel outer surface at the distal end.
In aspects, the distal end may be configured with a bottom ball check that may include a check ball held in place by a check ball retainer. The check ball may be proximate to a seat contact surface disposed in the mandrel. The check ball may be made of a dissolvable material.
The mandrel may include a circumferential taper formed on the mandrel outer surface near the proximate end. The circumferential taper may be formed at an angle φ of about 5 degrees with respect to a longitudinal axis of the mandrel. A length of the circumferential taper may be in a range of 0.5 inches to 0.75 inches.
The downhole tool may include a deformable member. The deformable member may be disposed around the mandrel, and may be proximate to the first cone. The deformable member may be configured to expand outward in a radial direction away from a longitudinal tool axis upon interaction with a pump down fluid. The deformable member may be configured to provide a larger hydraulic diameter of the downhole tool.
The system may include a grooved setting sleeve. Thus, the setting sleeve may include one or more grooves.
In aspects, the first slip may be a one-piece metal slip. The first slip may be treated with an induction hardening process. In other aspects, the first slip may be a composite slip further comprising a circular composite slip body having one-piece configuration. There may be an at least two slip grooves disposed therein. The composite slip body may further include a composite slip outer surface and a composite slip inner surface. An at least one of the at least two slip grooves may form a lateral opening in the composite slip body. The lateral opening may be defined by a first portion of slip material at a first slip end, a second portion of slip material at a second slip end, and a depth that extends from the composite slip outer surface to the composite slip inner surface.
Other embodiments of the disclosure pertain to a downhole system useable in a wellbore that may include one or more of: a work string comprising a downhole end; a setting sleeve coupled with the downhole end; and a downhole tool engaged with the setting sleeve during run-in.
The downhole tool may include a mandrel having a distal end; a proximate end; and a mandrel outer surface. The downhole tool may include a first slip disposed around the mandrel proximate to the distal end. There may be a first cone disposed around the mandrel, and proximate to a first side of the first slip.
The downhole tool may include a deformable member proximate to the first cone. The deformable member may be configured to expand outward in a radial direction away from a longitudinal tool axis upon interaction with a pump down fluid. The downhole tool may include a sealing element disposed around the mandrel. There may be a lower sleeve disposed around the mandrel, and proximate to a second side of the first slip. The lower sleeve may be coupled with the mandrel outer surface at the distal end.
In aspects, the setting sleeve may have a set of channels disposed in an outer surface of the setting sleeve. A cross-sectional shape of an at least one channel of the set of channels may be rounded.
The first slip may include a slip face surface configured with a set of mating holes. The lower sleeve may have a set of pins configured to engage the set of mating holes.
Other embodiments of the disclosure pertain to a downhole system for use in a wellbore that may include a work string comprising a downhole end; a setting sleeve coupled with the downhole end; and a downhole tool engaged with the setting sleeve during run-in. The downhole tool may include a mandrel, and an at least one slip. The mandrel may further include an external surface, a proximate end, and a distal end.
The setting sleeve may include one or more grooves.
The system may include a drop (or “frac”) ball engaged with the mandrel. The drop ball may be made of dissolvable material.
The least one slip may be a one-piece metal slip treated with an induction hardening process.
The at least one slip may be a one-piece slip made of filament wound material. The at least one slip may include one or more grooves.
These and other embodiments, features and advantages will be apparent in the following detailed description and drawings.
For a more detailed description of the present disclosure, reference will now be made to the accompanying drawings, wherein:
Herein disclosed are novel apparatuses, systems, and methods that pertain to and are usable for wellbore operations, details of which are described herein.
Referring now to
In accordance with embodiments of the disclosure, the tool 202 may be configured as a plugging tool, which may be set within the tubular 208 in such a manner that the tool 202 forms a fluid-tight seal against the inner surface 207 of the tubular 208. In an embodiment, the downhole tool 202 may be configured as a bridge plug, whereby flow from one section of the wellbore 213 to another (e.g., above and below the tool 202) is controlled. In other embodiments, the downhole tool 202 may be configured as a frac plug, where flow into one section 213 of the wellbore 206 may be blocked and otherwise diverted into the surrounding formation or reservoir 210.
In yet other embodiments, the downhole tool 202 may also be configured as a ball drop tool. In this aspect, a ball may be dropped into the wellbore 206 and flowed into the tool 202 and come to rest in a corresponding ball seat at the end of the mandrel 214. The seating of the ball may provide a seal within the tool 202 resulting in a plugged condition, whereby a pressure differential across the tool 202 may result. The ball seat may include a radius or curvature.
In other embodiments, the downhole tool 202 may be a ball check plug, whereby the tool 202 is configured with a ball already in place when the tool 202 runs into the wellbore. The tool 202 may then act as a check valve, and provide one-way flow capability. Fluid may be directed from the wellbore 206 to the formation with any of these configurations.
Once the tool 202 reaches the set position within the tubular, the setting mechanism or workstring 212 may be detached from the tool 202 by various methods, resulting in the tool 202 left in the surrounding tubular and one or more sections of the wellbore isolated. In an embodiment, once the tool 202 is set, tension may be applied to the adapter 252 until the threaded connection between the adapter 252 and the mandrel 214 is broken. For example, the mating threads on the adapter 252 and the mandrel 214 (256 and 216, respectively as shown in
Accordingly, the adapter 252 may separate or detach from the mandrel 214, resulting in the workstring 212 being able to separate from the tool 202, which may be at a predetermined moment. The loads provided herein are non-limiting and are merely exemplary. The setting force may be determined by specifically designing the interacting surfaces of the tool and the respective tool surface angles. The tool may 202 also be configured with a predetermined failure point (not shown) configured to fail or break. For example, the failure point may break at a predetermined axial force greater than the force required to set the tool but less than the force required to part the body of the tool.
Operation of the downhole tool 202 may allow for fast run in of the tool 202 to isolate one or more sections of the wellbore 206, as well as quick and simple drill-through to destroy or remove the tool 202. Drill-through of the tool 202 may be facilitated by components and sub-components of tool 202 made of drillable material that is less damaging to a drill bit than those found in conventional plugs. In an embodiment, the downhole tool 202 and/or its components may be a drillable tool made from drillable composite material(s), such as glass fiber/epoxy, carbon fiber/epoxy, glass fiber/PEEK, carbon fiber/PEEK, etc. Other resins may include phenolic, polyamide, etc. All mating surfaces of the downhole tool 202 may be configured with an angle, such that corresponding components may be placed under compression instead of shear.
The downhole tool 202 and/or one or more of its components may be 3D printed as would be apparent to one of skill in the art, such as via one or more methods or processes described in U.S. Pat. Nos. 6,353,771; 5,204,055; 7,087,109; 7,141,207; and 5,147, 587. See also information available at the websites of Z Corporation (www.zcorp.com); Prometal (www.prometal.com); EOS GmbH (www.eos.info); and 3D Systems, Inc. (www.3dsystems.com); and Stratasys, Inc. (www.stratasys.com and www.dimensionprinting.com) (applicable to all embodiments).
Referring now to
The presence of the bore 250 or other flowpath through the mandrel 214 may indirectly be dictated by operating conditions. That is, in most instances the tool 202 may be large enough in diameter (e.g., 4¾% inches) that the bore 250 may be correspondingly large enough (e.g., 1¼ inches) so that debris and junk can pass or flow through the bore 250 without plugging concerns. However, with the use of a smaller diameter tool 202, the size of the bore 250 may need to be correspondingly smaller, which may result in the tool 202 being prone to plugging. Accordingly, the mandrel may be made solid to alleviate the potential of plugging within the tool 202.
With the presence of the bore 250, the mandrel 214 may have an inner bore surface 247, which may include one or more threaded surfaces formed thereon. As such, there may be a first set of threads 216 configured for coupling the mandrel 214 with corresponding threads 256 of a setting adapter 252.
The coupling of the threads, which may be shear threads, may facilitate detachable connection of the tool 202 and the setting adapter 252 and/or workstring (212,
Referring briefly to
This type of configuration may allow, for example, where, in some applications, it may be desirable, to rip off or shear mandrel head 2159 instead of shearing threads 2116. In this respect, failing composite (or glass fibers) in tension may be potentially more accurate then shearing threads.
Referring again to
The downhole tool 202 may be run into wellbore (206,
The setting device(s) and components of the downhole tool 202 may be coupled with, and axially and/or longitudinally movable along mandrel 214. When the setting sequence begins, the mandrel 214 may be pulled into tension while the setting sleeve 254 remains stationary. The lower sleeve 260 may be pulled as well because of its attachment to the mandrel 214 by virtue of the coupling of threads 218 and threads 262. As shown in the embodiment of
As the lower sleeve 260 is pulled in the direction of Arrow A, the components disposed about mandrel 214 between the lower sleeve 260 and the setting sleeve 254 may begin to compress against one another. This force and resultant movement causes compression and expansion of seal element 222. The lower sleeve 260 may also have an angled sleeve end 263 in engagement with the slip 234, and as the lower sleeve 260 is pulled further in the direction of Arrow A, the end 263 compresses against the slip 234. As a result, slip(s) 234 may move along a tapered or angled surface 228 of a composite member 220, and eventually radially outward into engagement with the surrounding tubular (208,
Serrated outer surfaces or teeth 298 of the slip(s) 234 may be configured such that the surfaces 298 prevent the slip 234 (or tool) from moving (e.g., axially or longitudinally) within the surrounding tubular, whereas otherwise the tool 202 may inadvertently release or move from its position. Although slip 234 is illustrated with teeth 298, it is within the scope of the disclosure that slip 234 may be configured with other gripping features, such as buttons or inserts (e.g.,
Initially, the seal element 222 may swell into contact with the tubular, followed by further tension in the tool 202 that may result in the seal element 222 and composite member 220 being compressed together, such that surface 289 acts on the interior surface 288. The ability to “flower”, unwind, and/or expand may allow the composite member 220 to extend completely into engagement with the inner surface of the surrounding tubular.
The composite member 220 may provide other synergistic benefits beyond that of creating enhanced sealing. For example,
Referring again to
Because the sleeve 254 is held rigidly in place, the sleeve 254 may engage against a bearing plate 283 that may result in the transfer load through the rest of the tool 202. The setting sleeve 254 may have a sleeve end 255 that abuts against the bearing plate end 284. As tension increases through the tool 202, an end of the cone 236, such as second end 240, compresses against slip 242, which may be held in place by the bearing plate 283. As a result of cone 236 having freedom of movement and its conical surface 237, the cone 236 may move to the underside beneath the slip 242, forcing the slip 242 outward and into engagement with the surrounding tubular (208,
The second slip 242 may include one or more, gripping elements, such as buttons or inserts 278, which may be configured to provide additional grip with the tubular. The inserts 278 may have an edge or corner 279 suitable to provide additional bite into the tubular surface. In an embodiment, the inserts 278 may be mild steel, such as 1018 heat treated steel. The use of mild steel may result in reduced or eliminated casing damage from slip engagement and reduced drill string and equipment damage from abrasion.
In an embodiment, slip 242 may be a one-piece slip, whereby the slip 242 has at least partial connectivity across its entire circumference. Meaning, while the slip 242 itself may have one or more grooves (or notches, undulations, etc.) 244 configured therein, the slip 242 itself has no initial circumferential separation point. In an embodiment, the grooves 244 may be equidistantly spaced or disposed in the second slip 242. In other embodiments, the grooves 244 may have an alternatingly arranged configuration. That is, one groove 244A may be proximate to slip end 241, the next groove 244B may be proximate to an opposite slip end 243, and so forth.
The tool 202 may be configured with ball plug check valve assembly that includes a ball seat 286. The assembly may be removable or integrally formed therein. In an embodiment, the bore 250 of the mandrel 214 may be configured with the ball seat 286 formed or removably disposed therein. In some embodiments, the ball seat 286 may be integrally formed within the bore 250 of the mandrel 214. In other embodiments, the ball seat 286 may be separately or optionally installed within the mandrel 214, as may be desired.
The ball seat 286 may be configured in a manner so that a ball 285 seats or rests therein, whereby the flowpath through the mandrel 214 may be closed off (e.g., flow through the bore 250 is restricted or controlled by the presence of the ball 285). For example, fluid flow from one direction may urge and hold the ball 285 against the seat 286, whereas fluid flow from the opposite direction may urge the ball 285 off or away from the seat 286. As such, the ball 285 and the check valve assembly may be used to prevent or otherwise control fluid flow through the tool 202. The ball 285 may be conventionally made of a composite material, phenolic resin, etc., whereby the ball 285 may be capable of holding maximum pressures experienced during downhole operations (e.g., fracing). By utilization of retainer pin 287, the ball 285 and ball seat 286 may be configured as a retained ball plug. As such, the ball 285 may be adapted to serve as a check valve by sealing pressure from one direction, but allowing fluids to pass in the opposite direction.
The tool 202 may be configured as a drop ball plug, such that a drop ball may be flowed to a drop ball seat 259. The drop ball may be much larger diameter than the ball of the ball check. In an embodiment, end 248 may be configured with a drop ball seat surface 259 such that the drop ball may come to rest and seat at in the seat proximate end 248. As applicable, the drop ball (not shown here) may be lowered into the wellbore (206,
In other aspects, the tool 202 may be configured as a bridge plug, which once set in the wellbore, may prevent or allow flow in either direction (e.g., upwardly/downwardly, etc.) through tool 202. Accordingly, it should be apparent to one of skill in the art that the tool 202 of the present disclosure may be configurable as a frac plug, a drop ball plug, bridge plug, etc. simply by utilizing one of a plurality of adapters or other optional components. In any configuration, once the tool 202 is properly set, fluid pressure may be increased in the wellbore, such that further downhole operations, such as fracture in a target zone, may commence.
The tool 202 may include an anti-rotation assembly that includes an anti-rotation device or mechanism 282, which may be a spring, a mechanically spring-energized composite tubular member, and so forth. The device 282 may be configured and usable for the prevention of undesired or inadvertent movement or unwinding of the tool 202 components. As shown, the device 282 may reside in cavity 294 of the sleeve (or housing) 254. During assembly the device 282 may be held in place with the use of a lock ring 296. In other aspects, pins may be used to hold the device 282 in place.
The anti-rotation mechanism may provide additional safety for the tool and operators in the sense it may help prevent inoperability of tool in situations where the tool is inadvertently used in the wrong application. For example, if the tool is used in the wrong temperature application, components of the tool may be prone to melt, whereby the device 282 and lock ring 296 may aid in keeping the rest of the tool together. As such, the device 282 may prevent tool components from loosening and/or unscrewing, as well as prevent tool 202 unscrewing or falling off the workstring 212.
Drill-through of the tool 202 may be facilitated by the fact that the mandrel 214, the slips 234, 242, the cone(s) 236, the composite member 220, etc. may be made of drillable material that is less damaging to a drill bit than those found in conventional plugs. The drill bit will continue to move through the tool 202 until the downhole slip 234 and/or 242 are drilled sufficiently that such slip loses its engagement with the well bore. When that occurs, the remainder of the tools, which generally would include lower sleeve 260 and any portion of mandrel 214 within the lower sleeve 260 falls into the well. If additional tool(s) 202 exist in the well bore beneath the tool 202 that is being drilled through, then the falling away portion will rest atop the tool 202 located further in the well bore and will be drilled through in connection with the drill through operations related to the tool 202 located further in the well bore. Accordingly, the tool 202 may be sufficiently removed, which may result in opening the tubular 208.
Referring now to
The workstring 312 and setting sleeve 354 may be used collectively for activation of the tool 302 from an unset to set position in a manner like that of embodiments disclosed herein. The setting device(s) and components of the downhole tool 302 may be coupled with, and axially and/or longitudinally movable along mandrel 314, where the mandrel 314 may extend through the tool (or tool body) 302. When the setting sequence begins, as generally depicted in
For example, as the lower sleeve 360 is pulled and tension occurs in the tool 302, the components disposed about mandrel 314 between the lower sleeve 360 and the setting sleeve 354 may begin to compress against one another. The sleeve 354 may engage against a bearing plate 383 that may result in the transfer load through the rest of the tool 302. As a result of cone 336 having freedom of movement, the cone 336 may move to the underside beneath the slip 342, forcing the slip 342 outward and into engagement with the surrounding tubular 308.
This force and resultant movement causes compression and/or expansion of slip 342, which subsequently results in at least part of the tool 302 being raised or moved away from the bottommost surface 307 of the tubular 308. The upward force F3 that occurs during setting and urges the tool 302 upward, and downward force F2 that occurs from gravity on the workstring 312 and results in net force(s) incurred along the tool 302, including at point P1. The force at point P1 is at least partially due to the contact area A2 as a result of an external mandrel surface 345a of a proximate mandrel end 348 that contacts the inner surface 354a of the setting sleeve 354.
Generally tool 302 performance improves with centralization, such that, as shown in
Manufacturing of the external mandrel surface(s) 345a may be in a conventional manner, such as a machining process. The mandrel surface(s) 345a on the proximate end 348 may be rounded, or machined with enough incremental “flat” (linear) surfaces at different angles (or slopes) to form an apparent or effective rounded surface.
The use of such surfaces helps dramatically improve any aspect of reducing clearances and at friction, while at the same time the configuration of the proximate end 348 and the setting sleeve 354 limits or prevents “flopping around” of the same. The proximate end 348 may have a first length L1, which may extend about from the transition portion 349 to a most proximate end 348b. The proximate end 348 may have a second length L2, which may be comparable to an approximate length of the mandrel 314 that may contact or engage the setting sleeve 354, such as while in a run-in configuration.
Referring briefly to
In accordance with the disclosure various configurations of the proximate mandrel end 348, and particularly, an external mandrel surface 345a, may be useful for improving tool performance and reducing unwanted forces incurred by the mandrel during setting and operation. As already described, as a result of configurations related to area A2, the tool (302) provides the ability for the setting sleeve 354 to have less hang-up and binding on the mandrel 314.
The proximate end 348 may include an outer taper 348A, which may be generally linear with an approximate cross-sectional slope s1 made with reference to an appropriate x-y axis as would be apparent to one of skill. The outer taper 348A may suitable to help prevent the tool from getting stuck or binding. For example, during setting the use of a smaller tool may result in the tool binding on the setting sleeve, whereby the presence of the outer taper 348A will allow the tool mandrel end 348 to slide off easier from the setting sleeve 354. In an embodiment, the outer taper 348A may be formed at an angle of about 5 degrees with respect to an axis (358).
There may be a neck or transition portion 349, such that the mandrel may have variation with its outer diameter. The surface 345a of the transition portion 349 may be generally linear with an approximate cross-sectional slope s3 made with reference to an appropriate x-y axis as would be apparent to one of skill.
Between the taper 348A and the transition 349 may be another generally linear surface 354b with an approximate cross-sectional slope s2. In a run-in configuration, the surface 354b may be engaged with the sleeve 354 around the circumference of the parts, and as essentially illustrated by area A2. The surfaces of the mandrel end 348 may intersect at points, such as point(s) 397. The intersecting points 397 may be distinctly pointed, have rounded (or smoothed) surfaces), etc.
The external mandrel surface 345a of the proximate end 348 may have an apparent length L1, which may be with reference from a straight line from about the transition region 349 to an absolute furthest endpoint of the proximate end 348. The external mandrel surface 345a of the proximate end 348 may have an apparent length L2, which may be with reference from a straight line from about the distance of the surface 345a intended to contact, engage, or otherwise be nearmost to the setting sleeve 354 prior to setting, such as during run-in. In aspects, the length L1 is greater than the length L2. As would be apparent, the mandrel 314 may be configured with the end mandrel surface 345a having a greater area A1 than a proximate settling sleeve engagement surface A2.
Manufacturing of the external mandrel surface(s) 345a may be in a conventional manner, such as a machining process. The mandrel surface(s) 345a on the mandrel end 348 may be rounded, linear, combinations, etc. The surface(s) may be readily machined with enough incremental “flat” (linear) surfaces at different angles (or slopes) to form an apparent or effective rounded surface.
Referring briefly to
Because of the large pressures incurred, in using a sleeve 1954 with reduced hydraulic cross-section, it is important to maintain integrity. That is, any sleeve of embodiments disclosed herein must still be robust and inherent in strength to withstand shock pressure, setting forces, etc., and avoid component failure or collapse.
Although
Additional figures depict other embodiments of the disclosure, such as a channel(s) 1955 arranged in a non-axial or non-linear manner, for example, as spiral-wound, helical etc. It is worth noting that although embodiments of the sleeve channel 1955 shown herein may have the channel 1955 extending from one end of the sleeve 1957 to approximately the other end of the sleeve 1958, this need not be the case. Thus, the length of the channel L may be less than the length LS of the sleeve 1955. In addition, the channel 1955 need not be continuous, such that there may be discontinuous channels.
Other variants of sleeve 1954 having a certain channel groove pattern or cross-sectional shape are possible, including one or more channels 1955 having a “v-notch”, as well as an ‘offset’ V-notch, an opposite offset V-notch, a “square” notch, a rounded notch, and combinations thereof (not shown). Moreover, although the groups of channels may be disposed or arranged equidistantly apart, the groups may just as well have an unequal or random placement or distribution. Although the channel pattern or cross-sectional shape may be consistent and continuous, the scope of the disclosure is not limited to such a pattern. Thus, the pattern or cross-sectional shape may vary or have random discontinuities.
Yet other embodiments may include one or more channels 1955 disposed within the sleeve instead of on the outer surface. For example, sleeve 1954 may include a channel 1955 formed within the body (or wall thickness) of the sleeve, thus forming an inner passageway for fluid to flow therethrough.
Referring now to
The mandrel 314 may be sufficient in length, such that the mandrel may extend through a length of tool (or tool body) (202,
The ends 346, 348 of the mandrel 314 may include internal or external (or both) threaded portions. As shown in
The proximate end 348 may include an outer taper 348A. The outer taper 348A may help prevent the tool from getting stuck or binding. For example, during setting the use of a smaller tool may result in the tool binding on the setting sleeve, whereby the use of the outer taper 348 will allow the tool to slide off easier from the setting sleeve. In an embodiment, the outer taper 348A may be formed at an angle φ of about 5 degrees with respect to the axis 358. The length of the taper 348A may be about 0.5 inches to about 0.75 inches
There may be a neck or transition portion 349, such that the mandrel may have variation with its outer diameter. In an embodiment, the mandrel 314 may have a first outer diameter D1 that is greater than a second outer diameter D2. Conventional mandrel components are configured with shoulders (i.e., a surface angle of about 90 degrees) that result in components prone to direct shearing and failure. In contrast, embodiments of the disclosure may include the transition portion 349 configured with an angled transition surface 349A. A transition surface angle b may be about 25 degrees with respect to the tool (or tool component axis) 358.
The transition portion 349 may withstand radial forces upon compression of the tool components, thus sharing the load. That is, upon compression the bearing plate 383 and mandrel 314, the forces are not oriented in just a shear direction. The ability to share load(s) among components means the components do not have to be as large, resulting in an overall smaller tool size.
In addition to the first set of threads 316, the mandrel 314 may have a second set of threads 318. In one embodiment, the second set of threads 318 may be rounded threads disposed along an external mandrel surface 345 at the distal end 346. The use of rounded threads may increase the shear strength of the threaded connection.
Accordingly, the use of round threads may allow a non-axial interaction between surfaces, such that there may be vector forces in other than the shear/axial direction. The round thread profile may create radial load (instead of shear) across the thread root. As such, the rounded thread profile may also allow distribution of forces along more thread surface(s). As composite material is typically best suited for compression, this allows smaller components and added thread strength. This beneficially provides upwards of 5-times strength in the thread profile as compared to conventional composite tool connections.
With particular reference to
The use of a small curvature or radius 359A may be advantageous as compared to a conventional sharp point or edge of a ball seat surface. For example, radius 359A may provide the tool with the ability to accommodate drop balls with variation in diameter, as compared to a specific diameter. In addition, the surface 359 and radius 359A may be better suited to distribution of load around more surface area of the ball seat as compared to just at the contact edge/point of other ball seats.
Referring to
In other aspects, drop ball 2357 may be non-typical. For example, the drop ball 2357 may be a “smart” ball (not shown here) configured to monitor or measure downhole conditions, and otherwise convey information back to the surface or an operator, such as the ball(s) provided by Aquanetus Technology, Inc. or OpenField Technology
In other aspects, drop ball 2357 may be made from a composite material. In an embodiment, the composite material may be wound filament. Other materials are possible, such as glass or carbon fibers, phenolic material, plastics, fiberglass composite (sheets), plastic, etc.
The drop ball 2357 may be made from a dissolvable material. Thus, ball 2357 may be configured or otherwise designed to dissolve under certain conditions or various parameters, including those related to temperature, pressure, and composition, such as described in U.S. Pat. Nos. 7,350,582 and 8,211,248, each incorporated by reference herein in its entirety for all purposes.
The drop ball 2357 may be configured or otherwise made/manufactured as provided for in US Patent Publication Nos. 2012/0234538; 2012/0181032; and 2014/0120346, each of which being incorporated herein for all purposes in entirety (see also the ‘Magnum Fastball’).
As shown in
Referring now to
During pump down (or run in), the composite member 320 may ‘flower’ or be energized as a result of a pumped fluid, resulting in greater run-in efficiency (less time, less fluid required). During the setting sequence, the seal element 322 and the composite member 320 may compress together. As a result of an angled exterior surface 389 of the seal element 322 coming into contact with the interior surface 388 of the composite member 320, a deformable (or first or upper) portion 326 of the composite member 320 may be urged radially outward and into engagement the surrounding tubular (not shown) at or near a location where the seal element 322 at least partially sealingly engages the surrounding tubular. There may also be a resilient (or second or lower) portion 328. In an embodiment, the resilient portion 328 may be configured with greater or increased resilience to deformation as compared to the deformable portion 326.
The composite member 320 may be a composite component having at least a first material 331 and a second material 332, but composite member 320 may also be made of a single material. The first material 331 and the second material 332 need not be chemically combined. In an embodiment, the first material 331 may be physically or chemically bonded, cured, molded, etc. with the second material 332. Moreover, the second material 332 may likewise be physically or chemically bonded with the deformable portion 326. In other embodiments, the first material 331 may be a composite material, and the second material 332 may be a second composite material.
The composite member 320 may have cuts or grooves 330 formed therein. The use of grooves 330 and/or spiral (or helical) cut pattern(s) may reduce structural capability of the deformable portion 326, such that the composite member 320 may “flower” out. The groove 330 or groove pattern is not meant to be limited to any particular orientation, such that any groove 330 may have variable pitch and vary radially.
With groove(s) 330 formed in the deformable portion 326, the second material 332, may be molded or bonded to the deformable portion 326, such that the grooves 330 are filled in and enclosed with the second material 332. In embodiments, the second material 332 may be an elastomeric material. In other embodiments, the second material 332 may be 60-95 Duro A polyurethane or silicone. Other materials may include, for example, TFE or PTFE sleeve option-heat shrink. The second material 332 of the composite member 320 may have an inner material surface 368.
Different downhole conditions may dictate choice of the first and/or second material. For example, in low temp operations (e.g., less than about 250 F), the second material comprising polyurethane may be sufficient, whereas for high temp operations (e.g., greater than about 250 F) polyurethane may not be sufficient and a different material like silicone may be used.
The use of the second material 332 in conjunction with the grooves 330 may provide support for the groove pattern and reduce preset issues. With the added benefit of second material 332 being bonded or molded with the deformable portion 326, the compression of the composite member 320 against the seal element 322 may result in a robust, reinforced, and resilient barrier and seal between the components and with the inner surface of the tubular member (e.g., 208 in
Groove(s) 330 allow the composite member 320 to expand against the tubular, which may result in a formidable barrier between the tool and the tubular. In an embodiment, the groove 330 may be a spiral (or helical, wound, etc.) cut formed in the deformable portion 326. In an embodiment, there may be a plurality of grooves or cuts 330. In another embodiment, there may be two symmetrically formed grooves 330, as shown by way of example in
As illustrated by
In an embodiment, the groove(s) 330 or groove pattern may be a spiral pattern having constant pitch (p1 about the same as p2), constant radius (r3 about the same as r4) on the outer surface 364 of the deformable member 326. In an embodiment, the spiral pattern may include constant pitch (p1 about the same as p2), variable radius (r1 unequal to r2) on the inner surface 366 of the deformable member 326.
In an embodiment, the groove(s) 330 or groove pattern may be a spiral pattern having variable pitch (p1 unequal to p2), constant radius (r3 about the same as r4) on the outer surface 364 of the deformable member 326. In an embodiment, the spiral pattern may include variable pitch (p1 unequal to p2), variable radius (r1 unequal to r2) on the inner surface 366 of the deformable member 320.
As an example, the pitch (e.g., p1, p2, etc.) may be in the range of about 0.5 turns/inch to about 1.5 turns/inch. As another example, the radius at any given point on the outer surface may be in the range of about 1.5 inches to about 8 inches. The radius at any given point on the inner surface may be in the range of about less than 1 inch to about 7 inches. Although given as examples, the dimensions are not meant to be limiting, as other pitch and radial sizes are within the scope of the disclosure.
In an exemplary embodiment reflected in
The presence of groove(s) 330 may allow the composite member 320 to have an unwinding, expansion, or “flower” motion upon compression, such as by way of compression of a surface (e.g., surface 389) against the interior surface of the deformable portion 326. For example, when the seal element 322 moves, surface 389 is forced against the interior surface 388. Generally the failure mode in a high pressure seal is the gap between components; however, the ability to unwind and/or expand allows the composite member 320 to extend completely into engagement with the inner surface of the surrounding tubular.
Referring now to
The seal element 322 may be configured to buckle (deform, compress, etc.), such as in an axial manner, during the setting sequence of the downhole tool (202,
The seal element 322 may have one or more angled surfaces configured for contact with other component surfaces proximate thereto. For example, the seal element may have angled surfaces 327 and 389. The seal element 322 may be configured with an inner circumferential groove 376. The presence of the groove 376 assists the seal element 322 to initially buckle upon start of the setting sequence. The groove 376 may have a size (e.g., width, depth, etc.) of about 0.25 inches.
Slips. Referring now to
Slips 334, 342 may be used in either upper or lower slip position, or both, without limitation. As apparent, there may be a first slip 334, which may be disposed around the mandrel (214,
In embodiments, the slip 334 may be a poly-moldable material. In other embodiments, the slip 334 may be hardened, surface hardened, heat-treated, carburized, etc., as would be apparent to one of ordinary skill in the art. However, in some instances, slips 334 may be too hard and end up as too difficult or take too long to drill through.
Typically, hardness on the teeth 398 may be about 40-60 Rockwell. As understood by one of ordinary skill in the art, the Rockwell scale is a hardness scale based on the indentation hardness of a material. Typical values of very hard steel have a Rockwell number (HRC) of about 55-66. In some aspects, even with only outer surface heat treatment the inner slip core material may become too hard, which may result in the slip 334 being impossible or impracticable to drill-thru.
Thus, the slip 334 may be configured to include one or more holes 393 formed therein. The holes 393 may be longitudinal in orientation through the slip 334. The presence of one or more holes 393 may result in the outer surface(s) 307 of the metal slips as the main and/or majority slip material exposed to heat treatment, whereas the core or inner body (or surface) 309 of the slip 334 is protected. In other words, the holes 393 may provide a barrier to transfer of heat by reducing the thermal conductivity (i.e., k-value) of the slip 334 from the outer surface(s) 307 to the inner core or surfaces 309. The presence of the holes 393 is believed to affect the thermal conductivity profile of the slip 334, such that that heat transfer is reduced from outer to inner because otherwise when heat/quench occurs the entire slip 334 heats up and hardens.
Thus, during heat treatment, the teeth 398 on the slip 334 may heat up and harden resulting in heat-treated outer area/teeth, but not the rest of the slip. In this manner, with treatments such as flame (surface) hardening, the contact point of the flame is minimized (limited) to the proximate vicinity of the teeth 398.
With the presence of one or more holes 393, the hardness profile from the teeth to the inner diameter/core (e.g., laterally) may decrease dramatically, such that the inner slip material or surface 309 has a HRC of about ˜15 (or about normal hardness for regular steel/cast iron). In this aspect, the teeth 398 stay hard and provide maximum bite, but the rest of the slip 334 is easily drillable.
One or more of the void spaces/holes 393 may be filled with useful “buoyant” (or low density) material 400 to help debris and the like be lifted to the surface after drill-thru. The material 400 disposed in the holes 393 may be, for example, polyurethane, light weight beads, or glass bubbles/beads such as the K-series glass bubbles made by and available from 3M. Other low-density materials may be used.
The advantageous use of material 400 helps promote lift on debris after the slip 334 is drilled through. The material 400 may be epoxide or injected into the holes 393 as would be apparent to one of skill in the art.
The metal slip 334 may be treated with an induction hardening process. In such a process, the slip 334 may be moved through a coil that has a current run through it. As a result of physical properties of the metal and magnetic properties, a current density (created by induction from the e-field in the coil) may be controlled in a specific location of the teeth 398. This may lend to speed, accuracy, and repeatability in modification of the hardness profile of the slip 334. Thus, for example, the teeth 398 may have a RC in excess of 60, and the rest of the slip 334 (essentially virgin, unchanged metal) may have a RC less than about 15.
The slots 392 in the slip 334 may promote breakage. An evenly spaced configuration of slots 392 promotes even breakage of the slip 334.
First slip 334 may be disposed around or coupled to the mandrel (214,
When sufficient load is applied, the slip 334 compresses against the resilient portion or surface of the composite member (e.g., 220,
Referring briefly to
It is within the scope of the disclosure that tools described herein may include multiple composite members 1120, 1120A. The composite members 1120, 1120A may be identical, or they may different and encompass any of the various embodiments described herein and apparent to one of ordinary skill in the art. In embodiments, slip 334 and slip 342 may be the same material. For example, the downhole tool (e.g., 202, 302, etc.) may include two composite slips (see
Referring again to
Where the slip 342 is devoid of material at its ends, that portion or proximate area of the slip may have the tendency to flare first during the setting process. The arrangement or position of the grooves 344 of the slip 342 may be designed as desired. In an embodiment, the slip 342 may be designed with grooves 344 resulting in equal distribution of radial load along the slip 342. Alternatively, one or more grooves, such as groove 344B may extend proximate or substantially close to the slip end 343, but leaving a small amount material 335 therein. The presence of the small amount of material gives slight rigidity to hold off the tendency to flare. As such, part of the slip 342 may expand or flare first before other parts of the slip 342.
The slip 342 may have one or more inner surfaces with varying angles. For example, there may be a first angled slip surface 329 and a second angled slip surface 333. In an embodiment, the first angled slip surface 329 may have a 20-degree angle, and the second angled slip surface 333 may have a 40-degree angle; however, the degree of any angle of the slip surfaces is not limited to any particular angle. Use of angled surfaces allows the slip 342 significant engagement force, while utilizing the smallest slip 342 possible.
The use of a rigid single- or one-piece slip configuration may reduce the chance of presetting that is associated with conventional slip rings, as conventional slips are known for pivoting and/or expanding during run in. As the chance for pre-set is reduced, faster run-in times are possible.
The slip 342 may be used to lock the tool in place during the setting process by holding potential energy of compressed components in place. The slip 342 may also prevent the tool from moving as a result of fluid pressure against the tool. The second slip (342,
Referring briefly to
Referring now to
During setting, and as tension increases through the tool, an end of the cone 336, such as second end 340, may compress against the slip (see
Referring now to
As the lower sleeve 360 is pulled, the components disposed about mandrel between the may further compress against one another. The lower sleeve 360 may have one or more tapered surfaces 361, 361A which may reduce chances of hang up on other tools. The lower sleeve 360 may also have an angled sleeve end 363 in engagement with, for example, the first slip (234,
Referring briefly to
A possible difficulty with a one-piece metal slip is that instead of breaking evenly or symmetrically, it may be prone to breaking in a single spot or an uneven manner, and then fanning out (e.g., like a fan belt). If this it occurs, it may problematic because the metal slip (e.g., 334,
In contrast, the one-piece slip configuration is very durable, takes a lot of shock, and will not pre-set, but may require a configuration that urges uniform and even breakage. In accordance with embodiments disclosed herein, the metal slip 334 may be configured to mate or otherwise engage with pins 364A, which may aid breaking the slip 334 uniformly as a result of distribution of forces against the slip 334 (see
It is plausible a durable insert pin 364A may perform better than an integral pin/sleeve configuration of the lower sleeve 360 because of the huge massive forces that are encountered (i.e., 30,000 lbs). The pins 364A may be made of a durable metal, composite, etc., with the advantage of composite meaning the pins 364A are easily drillable.
This configuration is advantageous over changing breakage points on the metal slip because doing so would impact the strength of the slip, which is undesired. Accordingly, this configuration may allow improved breakage without impacting strength of the slip (i.e., ability to hold set pressure). In the instances where strength is not of consequence, a composite slip (i.e., a slip more readily able to break evening) could be used—use of metal slip is typically used for greater pressure conditions/setting requirements.
The pins 364A may be formed or manufactured by standard processes, and then cut (or machined, etc.) to an adequate or desired shape, size, and so forth. The pins 364A may be shaped and sized to a tolerance fit with slots 381B. In other aspects, the pins 364A may be shaped and sized to an undersized or oversized fit with slots 381B. The pins 364A may be held in situ with an adhesive or glue.
In embodiments one or more of the pins 364, 364A may have a rounded or spherical portion configured for engagement with the metal slip (see
The presence of the taper(s) 369 may be useful to help minimize displacement in the event the metal slip 334 inadvertently attempts to ‘hop up’ over one of the pins 364A in the instance the metal slip 334 did not break properly or otherwise.
One or more of the pins 364A may be configured with a ‘cut out’ portion that results in a pointed region on the inward side of the pin(s) 364A (see 7EE). This may aid in ‘crushing’ of the pin 364A during setting so that the pin 364A moves out of the way.
Referring briefly to
A downhole tool of embodiments disclosed herein may include the metal slip 334 disposed, for example, about the mandrel. The metal slip 334 may include (prior to setting) a one-piece circular slip body configuration. The metal slip 334 may include a face 397 configured with a set or plurality of mating holes 393A.
Referring now to
Thus, in accordance with embodiments of the disclosure the metal slip 334 may be configured for substantially even breakage of the metal slip body during setting. Prior to setting the metal slip 334 may have a one-piece circular slip body. That is, at least some part or aspects of the slip 334 has a solid connection around the entirety of the slip.
In an embodiment, the face (397,
The downhole tool may be configured for at least three portions of the metal slip 334 to be in gripping engagement with a surrounding tubular after setting. The set of stabilizer pins may be disposed in a symmetrical manner with respect to each other. The set of mating holes may be disposed in a symmetrical manner with respect to each other.
In accordance with embodiments disclosed herein, the metal slip 334 may be configured to mate or otherwise engage with pins 364A, which may aid breaking the slip 334 uniformly as a result of distribution of forces against the slip 334. The sleeve 360 may include a set of stabilizer pins configured to engage the set of mating holes.
Referring briefly to
Each of these aspects may contribute to the ability of the metal slip 334 to break a generally equal amount of distribution around the slip body circumference. That is, the metal slip 334 breaks in a manner where portions of the slip engage the surrounding tubular and the distribution of load is about equal or even around the slip 334. Thus, the metal slip 334 may be configured in a manner so that upon breakage load may be applied from the tool against the surrounding tubular in an approximate even or equal manner circumferentially (or radially).
The metal slip 334 may be configured in an optimal one-piece configuration that prevents or otherwise prohibits pre-setting, but ultimately breaks in an equal or even manner comparable to the intent of a conventional “slip segment” metal slip.
Referring now to
Because the sleeve (254,
Inner plate surface 319 may be configured for angled engagement with the mandrel. In an embodiment, plate surface 319 may engage the transition portion 349 of the mandrel 314. Lip 323 may be used to keep the bearing plate 383 concentric with the tool 202 and the slip 242. Small lip 323A may also assist with centralization and alignment of the bearing plate 383.
Referring briefly to
In accordance with embodiments disclosed herein, the metal slip may be configured to mate or otherwise engage with pins 364B, which may aid breaking the slip 334 uniformly as a result of distribution of forces against the slip 334.
It is believed a durable insert pin 364B may perform better than an integral configuration of the bearing plate 383 because of the huge massive forces that may be encountered (i.e., 30,000 lbs).
The pins 364B may be made of a durable metal, composite, etc., with the advantage of composite meaning the pins 364B may be easily drillable. This configuration may allow improved breakage without impacting strength of the slip (i.e., ability to hold set pressure). In the instances where strength is not of consequence, a composite slip (i.e., a slip more readily able to break evening) could be used—use of metal slip is used for greater pressure conditions/setting requirements.
Referring now to
In an embodiment, the bore (250,
The ball seat 386 may be configured in a manner so that when a ball (385,
As such, the ball 385 may be used to prevent or otherwise control fluid flow through the tool. As applicable, the ball 385 may be lowered into the wellbore (206,
Referring briefly to
In some applications, it may be desirable to configure a downhole tool (e.g., 202,
The check ball 2249 may be held in place by a check ball retainer 2250, which may be an insert, pin, etc. The check ball 2249 may seat within bottom ball seat 2248 and contact the mandrel 2214 at seat contact surface 2247. Because the check ball 2249 may be held in place, fluids and other materials such as sand (“flowback fluid”) either below or downstream from the tool (202) cannot flow past the tool and into a new zone (or zone upstream of the tool). This may be of significance when a new zone is a low pressure zone.
Accordingly, a first tool (202) may be used in a first completion/frac operation for a first zone. When the first operation is complete (or when it is otherwise desired), a second tool configured with a bottom ball check may be positioned within the wellbore, and flowback F from the first zone is prevented from flowing to a second zone. In this respect, the in situ bottom ball check configuration may be used for zone isolation functionality, whereas the use of a typical ball drop is used for tool activation (e.g., setting sequence).
The check ball 2249 may be removed by drillthru of the tool. However, in other embodiments it may be desirable to leave the tool in place. As such, the check ball 2249 may be removed as a result of degradation or dissolving. For example, the check ball 2249 may be configured or otherwise designed to dissolve under certain conditions or various parameters, including those related to temperature, pressure, and composition, such as described in U.S. Pat. No. 7,350,582, incorporated by reference herein in its entirety.
In this respect, under certain conditions, and/or after a certain amount of time lapse (such as 12 hours), check ball 2249 begins to dissolve/degrade eventually resulting in a fluid gap 2245 whereby flowback may pass thereby, and ultimately completely unseating and removal of obstruction, as shown in
Although described as a ball check, or a ball/retainer configuration, other embodiments are possible that provide for a controlled obstruction that prevents flowback, but ultimately allows flowback while leaving the tool (202) in the set position.
Referring now to
Encapsulation may help resolve presetting issues; the material 1290 is strong enough to hold in place or resist movement of, tool parts, such as the slips 1234, 1242, and sufficient in material properties to withstand extreme downhole conditions, but is easily breached by tool 1202 components upon routine setting and operation. Example materials for encapsulation include polyurethane or silicone; however, any type of material that flows, hardens, and does not restrict functionality of the downhole tool may be used, as would be apparent to one of skill in the art.
Referring now to
The tool 1402 may include a mandrel 1414 configured as a solid body. In other aspects, the mandrel 1414 may include a flowpath or bore 1450 formed therethrough (e.g., an axial bore). The bore 1450 may be formed as a result of the manufacture of the mandrel 1414, such as by filament or cloth winding around a bar. As shown in
In certain circumstances, a drop ball may not be a usable option, so the mandrel 1414 may optionally be fitted with the fixed plug 1403. The plug 1403 may be configured for easier drill-thru, such as with a hollow. Thus, the plug may be strong enough to be held in place and resist fluid pressures, but easily drilled through. The plug 1403 may be threadingly and/or sealingly engaged within the bore 1450.
The ends 1446, 1448 of the mandrel 1414 may include internal or external (or both) threaded portions. In an embodiment, the tool 1402 may be used in a frac service, and configured to stop pressure from above the tool 1401. In another embodiment, the orientation (e.g., location) of composite member 1420B may be in engagement with second slip 1442. In this aspect, the tool 1402 may be used to kill flow by being configured to stop pressure from below the tool 1402. In yet other embodiments, the tool 1402 may have composite members 1420, 1420A on each end of the tool.
Referring now to
As shown in
Because a bottom position slip is preferably set with a greater force, a metal slip may be desired. But where an operator requires a non-metallic tool or material (to the greatest extent possible), it may be beneficial to offset or otherwise displace any inadvertent setting force away from the composite slip, such as with a buffer.
During assembly, the second cone 2028, second slip 2042a, and lower sleeve 2060 may be positioned proximate to each other, respectively, and elongate members 2076, 2076a may then be inserted therethrough via lower sleeve channels 2061, 2061a, slip channels 2043, 2043a, and cone channels 2074, 2074a.
The elongate members 2076, 2076a may be held or otherwise retained in their position in any preferred manner that results in displacement of forces away from the cone/slip 2028/2034. As shown here, downhole tool 2002 may be configured with one or more shear retainer pins 2078, 2078a suitable to hold the elongate members 2076, 2076a in place. The pins 2078, 2078a may be brass shear pins. One or more pins 2078, 2078a may have a predetermined shear strength (or break point) of between about 500 to about 5000 lbs. During assembly, pins 2078, 2078a may be pressed into place through respective lower sleeve notches 2079, 2079a. The pins 2078, 2078a may also be pressed through, or in abutment to, the elongate members 2076, 2076a.
For greater strength, an insert 2080, 2080a may be used, as depicted here. Once properly assembled, the pin(s) 2078, 2078a may be inserted through the insert(s) 2080, 2080a via insert notch(es) 2079, 2079a. For tolerance control and better machining, the insert(s) 2080, 2080a may be metal. In an embodiment, the insert(s) 2080, 2080a may be aluminum.
In this configuration, the cone 2028 may be prevented from urging the slip 2042a to set since it is held in place by the arrangement of the members 2076, 2076a and retainer pins 2078, 2078a unless and/or until the breakpoint of the pins 2078, 2078a is otherwise exceeded.
The breakpoint of any one pin may be predetermined. Thus, for example, if three pins 2078, 2078a are used, the cumulative force must exceed three times the force to double shear the pin before slip 2028 may be able to urge slip 2042a to break or otherwise move to a set position. The pin shear force may be varied by number of pins, number of shears, pin diameter and material.
Downhole tool 2002 may include other components, such as a sealing element 2022, a bearing plate 2083, and composite member (220,
Embodiments of the downhole tool are smaller in size, which allows the tool to be used in slimmer bore diameters. Smaller in size also means there is a lower material cost per tool. Because isolation tools, such as plugs, are used in vast numbers, and are generally not reusable, a small cost savings per tool results in enormous annual capital cost savings.
A synergistic effect is realized because a smaller tool means faster drilling time is easily achieved. Again, even a small savings in drill-through time per single tool results in an enormous savings on an annual basis.
Advantageously, the configuration of components, and the resilient barrier formed by way of the composite member results in a tool that can withstand significantly higher pressures. The ability to handle higher wellbore pressure results in operators being able to drill deeper and longer wellbores, as well as greater frac fluid pressure. The ability to have a longer wellbore and increased reservoir fracture results in significantly greater production.
Embodiments of the disclosure provide for the ability to remove the workstring faster and more efficiently by reducing hydraulic drag.
As the tool may be smaller (shorter), the tool may navigate shorter radius bends in well tubulars without hanging up and presetting. Passage through shorter tool has lower hydraulic resistance and can therefore accommodate higher fluid flow rates at lower pressure drop. The tool may accommodate a larger pressure spike (ball spike) when the ball seats.
The composite member may beneficially inflate or umbrella, which aids in run-in during pump down, thus reducing the required pump down fluid volume. This constitutes a savings of water and reduces the costs associated with treating/disposing recovered fluids.
One piece slips assembly are resistant to preset due to axial and radial impact allowing for faster pump down speed. This further reduces the amount of time/water required to complete frac operations.
While preferred embodiments of the invention have been shown and described, modifications thereof can be made by one skilled in the art without departing from the spirit and teachings of the invention. The embodiments described herein are exemplary only, and are not intended to be limiting. Many variations and modifications of the invention disclosed herein are possible and are within the scope of the invention. Where numerical ranges or limitations are expressly stated, such express ranges or limitations should be understood to include iterative ranges or limitations of like magnitude falling within the expressly stated ranges or limitations. The use of the term “optionally” with respect to any element of a claim is intended to mean that the subject element is required, or alternatively, is not required. Both alternatives are intended to be within the scope of the claim. Use of broader terms such as comprises, includes, having, etc. should be understood to provide support for narrower terms such as consisting of, consisting essentially of, comprised substantially of, and the like.
Accordingly, the scope of protection is not limited by the description set out above but is only limited by the claims which follow, that scope including all equivalents of the subject matter of the claims. Each and every claim is incorporated into the specification as an embodiment of the present invention. Thus, the claims are a further description and are an addition to the preferred embodiments of the present invention. The inclusion or discussion of a reference is not an admission that it is prior art to the present invention, especially any reference that may have a publication date after the priority date of this application. The disclosures of all patents, patent applications, and publications cited herein are hereby incorporated by reference, to the extent they provide background knowledge; or exemplary, procedural or other details supplementary to those set forth herein.
Claims
1. A downhole system for use in a wellbore, the downhole system comprising:
- a work string comprising a downhole end, and a setting tool;
- a setting sleeve coupled with the downhole end; and
- a downhole tool engaged with the setting sleeve during run-in, the downhole tool further comprising: a mandrel made of a composite material, the mandrel further comprising: a distal end; a proximate end comprising a set of threads; and a mandrel outer surface; a bearing plate disposed around the mandrel; a first slip disposed around the mandrel proximate to the distal end, the first slip further comprising: a first slip body having a one-piece configuration; a first slip outer surface; and at least one lateral groove in the first slip body that is defined by a depth that extends from the first slip outer surface to a first slip inner surface; a first cone disposed around the mandrel, and proximate to a first side of the first slip; a second slip disposed around the mandrel; a second cone disposed around the mandrel, and proximate to a first side of the second slip; a sealing element disposed around the mandrel, and between the first cone and the second cone; and a lower sleeve disposed around the mandrel, and proximate to a second side of the first slip, wherein the lower sleeve is coupled with the mandrel outer surface at the distal end,
- wherein the setting sleeve comprises a set of linear channels disposed in an outer surface of the setting sleeve, wherein an at least one channel of the set of channels extends from a first sleeve end to a second sleeve end, and wherein the setting tool comprises an adapter coupled with the set of threads.
2. The downhole system of claim 1, wherein the distal end is configured with a bottom ball check comprising a check ball held in place by a check ball retainer.
3. The downhole system of claim 2, wherein the check ball is proximate to a seat contact surface disposed in the mandrel.
4. The downhole system of claim 1, wherein the downhole tool further comprises a deformable member proximate to the first cone, the deformable member configured to expand outward in a radial direction away from a longitudinal tool axis upon interaction with a pump down fluid.
5. The downhole system of claim 1, wherein the setting sleeve comprises a plurality of grooves.
6. The downhole system of claim 5, wherein an at least one channel of the plurality of grooves is linear in length and disposed in an outer surface of the setting sleeve.
7. The downhole system of claim 1, wherein the first slip is a heat treated one-piece metal slip configured with a hardness profile comprising the first slip outer surface having a Rockwell hardness Scale C (HRC), in the range of 40 to 60, and the inner slip surface having a Rockwell hardness Scale C (HRC) in the range of 10 to 25.
8. The downhole system of claim 1, wherein the first slip further comprises a slip face surface configured with a set of mating holes, and wherein the lower sleeve comprises a set of pins configured to engage the set of mating holes.
9. The downhole system of claim 1, wherein the setting sleeve comprises a set of three groups of channels disposed in an outer surface of the setting sleeve, wherein each group comprises between 1 and 3 channels, and wherein the cross-sectional shape of an at least one channel of the set of three groups is rounded.
10. The downhole system of claim 1, wherein the second slip further comprises:
- a composite slip further comprising a circular composite slip body having one-piece configuration, and an at least two slip grooves disposed therein,
- wherein the composite slip body further comprises a composite slip outer surface and a composite slip inner surface, wherein at least one of the at least two slip grooves forms a lateral opening in the composite slip body that is defined by a first portion of slip material at a first slip end, a second portion of slip material at a second slip end, and a depth that extends from the composite slip outer surface to the composite slip inner surface.
11. A downhole system for use in a wellbore, the downhole system comprising:
- a work string comprising a downhole end, and a setting tool;
- a setting sleeve coupled with the downhole end; and
- a downhole tool engaged with the setting sleeve during run-in, the downhole tool further comprising: a mandrel further comprising: a distal end; a proximate end; and a mandrel outer surface; a first slip disposed around the mandrel proximate to the distal end; a first cone disposed around the mandrel, and proximate to a first side of the first slip; a deformable member proximate to the first cone, the deformable member configured to expand outward in a radial direction away from a longitudinal tool axis upon interaction with a pump down fluid; a sealing element disposed around the mandrel; and a lower sleeve disposed around the mandrel, and proximate to a second side of the first slip, wherein the lower sleeve is coupled with the mandrel outer surface at the distal end,
- wherein the setting sleeve comprises a set of linear channels disposed in an outer surface of the setting sleeve, wherein an at least one channel of the set of channels extends from a first sleeve end to a second sleeve end, wherein a lateral cross-sectional shape of the at least one channel is rounded, and wherein the setting tool comprises an adapter coupled with the proximate end.
12. The downhole system of claim 11, the system further comprising a drop ball engaged with the mandrel, wherein the drop ball is made of dissolvable material.
13. The downhole system of claim 11, wherein the first slip is a one-piece metal slip that comprises columns of serrated teeth.
14. The downhole system of claim 11, wherein the first slip further comprises:
- a composite slip further comprising a circular composite slip body having one-piece configuration, and an at least two slip grooves disposed therein,
- wherein the composite slip body further comprises a composite slip outer surface and a composite slip inner surface, wherein at least one of the at least two slip grooves forms a lateral opening in the composite slip body that is defined by a first portion of slip material at a first slip end, a second portion of slip material at a second slip end, and a depth that extends from the composite slip outer surface to the composite slip inner surface.
15. A downhole system for use in a wellbore, the downhole system comprising:
- a work string comprising a downhole end, and a setting tool further comprising a setting adapter;
- a setting sleeve coupled with the downhole end; and
- a downhole tool engaged with the setting sleeve during run-in, the downhole tool further comprising: a mandrel made of a composite material, the mandrel further comprising: a distal end; a proximate end; a flowbore extending from the distal end to the proximate end; and an outer surface, wherein the outer surface at the distal end is configured with a set of threads; a bearing plate disposed around the mandrel; a first metal slip disposed around the mandrel proximate to the distal end, the first metal slip further comprising: a first metal slip body having a one-piece configuration; an outer metal slip surface further comprising columns of serrated teeth; and at least one lateral groove in the first metal slip body that is defined by a depth that extends the outer metal slip surface to a first metal slip inner surface; a first cone disposed around the mandrel, and proximate to a first side of the first metal slip; a second slip disposed around the mandrel; a second cone disposed around the mandrel, and proximate to a first side of the second slip; a sealing element disposed around the mandrel, and between the first cone and the second cone; and a lower sleeve disposed around the mandrel, and proximate to a second side of the first metal slip,
- wherein the setting sleeve comprises a set of linear channels disposed in an outer surface of the setting sleeve, wherein an at least one channel of the set of channels extends from a first sleeve end to a second sleeve end, wherein a lateral cross-sectional shape of the at least one channel is rounded, wherein the lower sleeve is configured with sleeve threads that are coupled with the set of threads, and wherein the setting adapter is engaged with an inner surface of the flowbore.
16. The downhole system of claim 15, wherein the second slip further comprises:
- a composite slip further comprising a circular composite slip body having one-piece configuration, and an at least two slip grooves disposed therein,
- wherein the composite slip body further comprises a composite slip outer surface and a composite slip inner surface, wherein at least one of the at least two slip grooves forms a lateral opening in the composite slip body that is defined by a first portion of slip material at a first slip end, a second portion of slip material at a second slip end, and a depth that extends from the composite slip outer surface to the composite slip inner surface.
2230712 | February 1941 | Bendeler et al. |
2683492 | July 1954 | Baker |
2797758 | July 1957 | Showalter |
3163225 | December 1964 | Perkins |
3343607 | September 1967 | Current |
3422898 | January 1969 | Conrad |
3687196 | August 1972 | Mullins |
3769127 | October 1973 | Goldsworthy et al. |
3776561 | December 1973 | Haney |
4359090 | November 16, 1982 | Luke |
4388971 | June 21, 1983 | Peterson |
4436150 | March 13, 1984 | Barker |
4437516 | March 20, 1984 | Cockrell |
4440223 | April 3, 1984 | Akkerman |
4469172 | September 4, 1984 | Clark |
4711300 | December 8, 1987 | Wardlaw et al. |
4784226 | November 15, 1988 | Wyatt |
5025858 | June 25, 1991 | Glaser |
5048606 | September 17, 1991 | Allwin |
5113940 | May 19, 1992 | Glaser |
5147857 | September 15, 1992 | Raddatz et al. |
5224540 | July 6, 1993 | Streich et al. |
5246069 | September 21, 1993 | Glaser et al. |
5253714 | October 19, 1993 | Davis et al. |
5333685 | August 2, 1994 | Gilbert |
5346014 | September 13, 1994 | Ross |
5376200 | December 27, 1994 | Hall |
5449040 | September 12, 1995 | Milner |
5484040 | January 16, 1996 | Penisson |
5819846 | October 13, 1998 | Bolt et al. |
5839515 | November 24, 1998 | Yuan et al. |
5842517 | December 1, 1998 | Coone |
5927403 | July 27, 1999 | Dallas |
5967352 | October 19, 1999 | Repp |
5984007 | November 16, 1999 | Yuan |
6167963 | January 2, 2001 | McMahan et al. |
6241018 | June 5, 2001 | Eriksen |
6353771 | March 5, 2002 | Southland |
6354372 | March 12, 2002 | Carisella et al. |
6425442 | July 30, 2002 | Latiolais et al. |
6491116 | December 10, 2002 | Berscheidt et al. |
6578638 | June 17, 2003 | Guillory |
6708768 | March 23, 2004 | Slup et al. |
6712153 | March 30, 2004 | Turley et al. |
6899181 | May 31, 2005 | Simpson et al. |
7044230 | May 16, 2006 | Starr et al. |
7087109 | August 8, 2006 | Bredt et al. |
7093664 | August 22, 2006 | Todd et al. |
7255178 | August 14, 2007 | Slup et al. |
7350569 | April 1, 2008 | Collins et al. |
7350582 | April 1, 2008 | McKeachnie et al. |
7475736 | January 13, 2009 | Lehr et al. |
7735549 | June 15, 2010 | Nish et al. |
7740079 | June 22, 2010 | Clayton et al. |
7762323 | July 27, 2010 | Frazier |
7980300 | July 19, 2011 | Roberts et al. |
8002030 | August 23, 2011 | Turley et al. |
8016295 | September 13, 2011 | Guest et al. |
8079413 | December 20, 2011 | Frazier |
8113276 | February 14, 2012 | Greenlee et al. |
8127851 | March 6, 2012 | Misselbrook |
8167033 | May 1, 2012 | White |
8205671 | June 26, 2012 | Branton |
8211248 | July 3, 2012 | Marya |
8231947 | July 31, 2012 | Vaidya et al. |
8267177 | September 18, 2012 | Vogel et al. |
D673182 | December 25, 2012 | Frazier |
8336616 | December 25, 2012 | McClinton |
8381809 | February 26, 2013 | White |
8459346 | June 11, 2013 | Frazier |
8469088 | June 25, 2013 | Shkurti et al. |
8567492 | October 29, 2013 | White |
8596347 | December 3, 2013 | Valencia et al. |
8839855 | September 23, 2014 | McClinton et al. |
8770276 | July 8, 2014 | Nish et al. |
8770280 | July 8, 2014 | Buytaert et al. |
8887818 | November 18, 2014 | Carr et al. |
8893780 | November 25, 2014 | Greenlee et al. |
9416617 | August 16, 2016 | Wiese et al. |
9708878 | July 18, 2017 | Cooke, Jr. |
9714551 | July 25, 2017 | Okura et al. |
9790763 | October 17, 2017 | Fripp et al. |
D806136 | December 26, 2017 | Saulou et al. |
9845658 | December 19, 2017 | Nish et al. |
10156120 | December 18, 2018 | Davies |
20030000710 | January 2, 2003 | Turley |
20030188876 | October 9, 2003 | Vick et al. |
20030226659 | December 11, 2003 | Smith |
20030226660 | December 11, 2003 | Winslow et al. |
20040003928 | January 8, 2004 | Frazier |
20040045723 | March 11, 2004 | Slup et al. |
20050183864 | August 25, 2005 | Trinder |
20060243455 | November 2, 2006 | Telfer |
20070039742 | February 22, 2007 | Costa |
20070119600 | May 31, 2007 | Slup et al. |
20080128133 | June 5, 2008 | Turley et al. |
20080196879 | August 21, 2008 | Broome et al. |
20080264627 | October 30, 2008 | Roberts et al. |
20090011247 | January 8, 2009 | Barlow |
20090038790 | February 12, 2009 | Barlow |
20090090516 | April 9, 2009 | Delucia et al. |
20090229424 | September 17, 2009 | Montgomery |
20090236091 | September 24, 2009 | Hammami et al. |
20100155050 | June 24, 2010 | Frazier |
20100263876 | October 21, 2010 | Frazier |
20110024134 | February 3, 2011 | Buckner |
20110048740 | March 3, 2011 | Ward et al. |
20110048743 | March 3, 2011 | Stafford et al. |
20110088891 | April 21, 2011 | Stout |
20110094802 | April 28, 2011 | Vatne |
20110232899 | September 29, 2011 | Porter |
20110259610 | October 27, 2011 | Shkurti et al. |
20110277989 | November 17, 2011 | Frazier |
20110290473 | December 1, 2011 | Frazier |
20120061105 | March 15, 2012 | Neer et al. |
20120125637 | May 24, 2012 | Chenault |
20120125642 | May 24, 2012 | Chenault |
20120181032 | July 19, 2012 | Naedler et al. |
20120234538 | September 20, 2012 | Martin et al. |
20120279700 | November 8, 2012 | Frazier |
20130098600 | April 25, 2013 | Roberts |
20130240201 | September 19, 2013 | Frazier |
20130306331 | November 21, 2013 | Bishop et al. |
20140020911 | January 23, 2014 | Martinez |
20140027127 | January 30, 2014 | Frazier et al. |
20140090831 | April 3, 2014 | Young et al. |
20140116677 | May 1, 2014 | Sherlin |
20140120346 | May 1, 2014 | Rochen |
20140224476 | August 14, 2014 | Frazier |
20140374163 | December 25, 2014 | Rui et al. |
20150013996 | January 15, 2015 | Davies et al. |
20150068728 | March 12, 2015 | Stage et al. |
20150144348 | May 28, 2015 | Okura et al. |
20150354313 | December 10, 2015 | McClinton et al. |
20160123104 | May 5, 2016 | Harris |
20160138362 | May 19, 2016 | Dockweiler |
20160160591 | June 9, 2016 | Xu et al. |
20160201427 | July 14, 2016 | Fripp et al. |
20160265305 | September 15, 2016 | Davies et al. |
20160281458 | September 29, 2016 | Greenlee |
20170044859 | February 16, 2017 | Blair |
20170260824 | September 14, 2017 | Kellner et al. |
20170284167 | October 5, 2017 | Takahashi et al. |
0504848 | September 1992 | EP |
0890706 | January 1993 | EP |
1643602 | April 2006 | EP |
2007014339 | February 2007 | WO |
2008100644 | August 2008 | WO |
20091128853 | September 2009 | WO |
2011097091 | August 2011 | WO |
2016182545 | November 2016 | WO |
- International Preliminary Report on Patentability, PCT/US2012/051938, 6 pages, dated Feb. 25, 2014.
- International Search Report, PCT/US2012/051938, 3 pages, dated Jan. 3, 2013.
- International Preliminary Report on Patentability, PCT/US2012/051940, 6 pages, dated Feb. 25, 2014.
- Written Opinion dated Jan. 3, 2013 for Intl App No. PCT/US2012/051938 (5 pages).
- Search Report and Written Opinion dated Feb. 21, 2013 for Intl App No. PCT/US2012/051936 (9 pages).
- Search Report and Written Opinion dated Feb. 27, 2013 for Intl App No. PCT/US2012/051940 (10 pages).
- Search Report dated Mar. 11, 2013 for Intl App No. PCT/US2012/051934 (3 pages).
- Lehr et al., “Best Practices for Multizone Isolation Using Composite Plugs,” Society of Petroleum Engineers, SPE 142744 ConocoPhillips and Baker Hughes Conference Paper, dated Jun. 8, 2011 (40 pgs).
- International Preliminary Report on Patentability, PCT/US2012/051934, 6 pages, dated Feb. 25, 2014.
- International Preliminary Report on Patentability, PCT/US2012/051936, 5 pages, dated Feb. 25, 2014.
- Search Report dated Feb. 27, 2013 for Intl App No. PCT/US2012/051940 (3 pages).
- Search Report dated Feb. 21, 2013 for Intl App No. PCT/US2012/051936 (3 pages).
- Search Report and Written Opinion dated Mar. 11, 2013 for Intl App No. PCT/US2012/051934 (10 pages).
Type: Grant
Filed: May 26, 2016
Date of Patent: Apr 2, 2019
Patent Publication Number: 20160265305
Assignee: Downhole Technology, LLC (Houston, TX)
Inventors: Evan Lloyd Davies (Houston, TX), Duke VanLue (Tomball, TX)
Primary Examiner: Blake E Michener
Application Number: 15/164,950
International Classification: E21B 23/01 (20060101); E21B 23/06 (20060101); E21B 33/12 (20060101); E21B 34/00 (20060101); E21B 43/26 (20060101); E21B 33/124 (20060101); E21B 33/128 (20060101); E21B 33/129 (20060101); E21B 33/134 (20060101);